HOUSE BILL NO. 50 "An Act relating to the geologic storage of carbon dioxide; and providing for an effective date." 1:35:10 PM AT EASE 1:35:57 PM RECONVENED Co-Chair Foster continued to review the agenda. 1:36:41 PM NICHOLAS FULFORD, SENIOR DIRECTOR, GAS AND ENERGY TRANSITION, GAFFNEYCLINE, introduced himself and the PowerPoint presentation "CCUS Value Chain and Business Case" dated May 3, 2023 (copy on file). He shared that he had worked on around a dozen CCS [carbon capture storage] projects worldwide, but predominately in Texas and Louisiana. He began on slide 2 and provided the agenda for the presentation. He stated that the industry was unfolding at a rapid rate. He relayed there were quite a few useful lessons that could be drawn from activities around the world. One of the features of the journey was that the different sequestration agreements had reached an advanced stage in their discussions so that cost stack and pore space leasing costs were starting to come to the surface. As the contracts became more sophisticated there were a number of commercial considerations emerging. He reported that the environment for CCS in Alaska was very different from Texas, Louisiana, and many other parts of the world. Mr. Fulford moved to slide 3 titled "Significance of State Related Charges in Development." He shared that in the context of the CCS industry, Alaska was in a fairly early stage. He elaborated that many of the projects in Texas and Louisiana had reached fully termed sequestration agreements typically between an emitter (e.g., a petrochemical plant or power station) and transportation storage companies (T&S). He detailed that T&S entities had to address where the carbon dioxide (CO2) was sequestered, and part of their contractual framework pertained to pore space leasing agreements. He expected the journey in Alaska to move through the same kind of phase. He relayed that the focus had been on the geology and rock properties in the past few months and the outcome of the work was to demonstrate that the state had considerable potential. Mr. Fulford continued reviewing stages on slide 3. The second stage was techno-economic project feasibility, which included a high level dialogue with potential emitters and people interested in storing CO2 and a more advanced perspective on pore space leasing. He noted it would include the kind of regulatory and legislative framework HB 50 was designed to address. Mr. Fulford moved to the third phase, which would be termed a pre-financial investment decision (FID) phase. He detailed that the emitters and the sequestering T&S companies were finding it useful to adopt a heads of agreement framework, which entailed an eight to ten-page agreement (that was not typically legally binding) to provide some assurance for lenders and the industries looking to sequester their carbon. He expounded that part of the agreement would likely include a reasonably detailed explanation of the pore space arrangements and location. At that point, much more detailed financial modeling would occur, including levelized cost storage and taxes. The fourth phase FID would include an array of contracts, which would be carefully scrutinized by lenders, particularly if any project finance was involved. There would also be an EPC or development contract to look at construction. 1:42:01 PM Representative Hannan asked what the last term [EPC] used by Mr. Fulford stood for. Mr. Fulford replied that EPC stood for engineering, procurement, and construction (EPC) contract. 1:42:26 PM Representative Galvin referenced the technical feasibility stage shown on slide 3. She recalled discussion in committee the previous week about transportation of a product thousands of miles to another location. She found it to be a significant barrier to the project concept. She remarked that the committee had not yet seen the size or type of container needed. She thought it was an important part of the plan. Alternatively, she considered that perhaps there was only thought about oil and gas on the North Slope, which was an entirely different vision. She asked for Mr. Fulford's comments. Mr. Fulford responded that the distance between the emitting source and the sequestration site was a critical part of the picture. He stated that the distance was relatively short for most of the existing projects or projects in development. He highlighted an ammonia plant where an injection well was being drilled within the plant boundary, which created substantial savings. He estimated that for the Gulf Coast, the distance the economics were sustainable was about 50 miles. He elaborated that at that point the compression in the pipeline tariffs started to encroach. He noted it was within the current envelope of the 45Q tax credits of about $85 per ton and the capture, transport, and sequestration came out of that. The marine transport of CO2 was being done between Denmark and Norway and was a relatively groundbreaking and developing technology. Although there had not been any largescale CO2 marine transportation vessels built yet, they were on the drawing board. He relayed that to move CO2 from Southeast Asia to Alaska in a large oceangoing CO2 vessel would cost about $50 per ton. He stated it would be comparable to a complex CO2 capture facility. Representative Galvin surmised that if the ship were to be built and the [transportation] cost was $50 per ton, it sounded like the market was much higher than in other places. She remarked that she could be wrong and perhaps Japan and Asia had other market choices. She asked if Alaska was really a good choice for them. Mr. Fulford responded that there were a number of energy intensive Asian economies without any readily available CO2 sequestration facilities; therefore, a number of them were looking actively at cross border CO2 export projects, in which case the distance and complexity was a factor. The regulatory ability to monitor and measure and be confident in secure storage was also particularly important. He stated that one interesting synergy with respect to Alaska was the potential export of LNG [liquid natural gas] and the import of CO2. There were a number of Japanese companies looking at the concept. Although the economics and technology were yet to be determined, it was one of the factors that made CO2 imports more relevant than other ones. Representative Galvin asked Mr. Fulford to speak to the economics of a future situation where the technology existed for Asia or another country to ship its carbon to Alaska for sequestration and Alaska shipped out its LNG or another gas product. She asked what the revenue would look like for Alaska. Mr. Fulford responded that the strategic scale of CCUS [carbon capture, utilization, and storage] in Alaska was significant on a global level. He stated it was useful to keep in mind that the numbers and volumes were material when turning them into revenue numbers. He relayed that moving LNG from Alaska to Asia cost about $1.00 per million Btu [British thermal unit], which corresponded to about $50 per ton. He elaborated that when exporting LNG, the exporter bore the return cost of the empty ship. He stated that equally with CO2 "you'd be doing the same." He relayed that in theory, if the activities could be combined into one business model, it would mean the potential for halving the costs, which would create much more economic opportunity. He believed the concept was a number of years away, but it was worthy of exploration for Alaska's oil and gas future. He noted there were other strategies available including processing gas into ammonia or another organic compound, which was more transportable than hydrogen and could be used to export instead of gas. He stated that CCUS was a facilitating technology that would aid in the process. 1:51:09 PM Representative Josephson referenced the terms price discovery and levelized cost storage used by Mr. Fulford. He asked for an explanation of the terms. Mr. Fulford responded that there were dozens of emitters in the U.S. Gulf Coast energy corridor who were all looking for cost effective storage of their CO2. There were perhaps half a dozen viable storage candidates. He elaborated that currently the dialogue was going back and forth between emitters and storage entities and price discovery was the negotiation process of what was almost a commodity price. Levelized cost was a term associated with carbon projects and was a way of turning the capital and operating costs into a tariff. He elaborated that the levelized cost of CO2 storage may be $20 per ton, which meant that financing the capital and operating expenditures would require a $20 per ton tariff over a 20-year period in order to pay it off. 1:53:32 PM Co-Chair Johnson referred to the CO2 backhaul. She asked whether natural gas was a liquid that compressed at relatively the same rate [as CO2] making it possible to use the same ships [for transportation]. Mr. Fulford explained that the concept of LNG out and CO2 back had economic advantage, but the technology did not yet exist. The factors mentioned by Co-Chair Johnson were key and would have to be addressed. He believed it would be many years before the option was available. Co-Chair Johnson referenced the number of different entities from which the CO2 might be received. She asked if CO2 gas was pure or included other chemical compounds. She asked if it varied by company. Mr. Fulford replied that for a point to point CCS scheme, the quality of the CO2 was much less important as long as it was in a form that could be easily injected and would remain in the reservoir. He relayed that CO2 quality was key for emerging industrial hubs in the same way that gas transmission system had a certain spec, which had to be adhered to. He stated in that case, some emitters may place additional costs in pretreating CO2 to get it to the right quality. 1:56:28 PM Mr. Fulford advanced to slide 4 and the unit technical cost of some examples of real life sequestration projects. He detailed that the technical cost amounted to the upfront capital expenditures and 20 years of operating expenditures. He noted the information was useful as a comparison between different concepts, but it did not translate into a tariff. For the most part, the capture of CO2 was a significantly higher proportion of capital than lease storage. He relayed that the transport and to some extent the compression were variable. The example on the left of the slide was an industrial hub concept and showed relatively small transport and storage cost, reflecting economies of scale in the unit technical cost. The other two examples on the slide showed a gas processing project and an LNG acid gas pre-treatment project. He explained that the predominance of capital and operating expense required for the two projects was for the capture. He noted he would go into additional detail on the numbers in the next couple of slides. Mr. Fulford moved to slide 5 titled "Example Costs for a 200 to 250MMscfd Project (3.9 to 4.8 MTPA)." The slide corresponded to the gas processing and LNG acid gas pre- treatment projects [shown on slide 4]. He noted the two projects were very similar. He pointed out that a certain amount of compression was required to bring the CO2 up to the required critical pressures. The slide showed $77.3 million in compression capital expenditure and $40 million for injection wells. The other costs were less in descending order of magnitude. The example project was 4 to 5 million tons per annum (MTPA) of CO2 with approximately $125 million in upfront capital expenditures. The right side of the chart listed operating expenditures with the two key components being fuel for the compression and monitoring cost of injection wells and monitoring equipment, which was very expensive. The total operating expenditure was about $8 million. Mr. Fulford continued to slide 6 and went through a potential hypothetical scenario in terms of what the cost may be for leasing the pore space. The scenario applied a $1 per ton additional cost for the pore space lease, which changed the numbers accordingly. The change added about $4.5 million per annum of operating expenditures (a 35 percent increase compared to the example without pore space leasing). Mr. Fulford moved to slide 7 and highlighted a scenario where the pore space lease was capitalized and moved upfront as a capacity charge or something similar. He detailed that at a 10 percent discount rate the pore space lease (capital) came to about $38 million, which added about 30 percent (the capital expenditure would go from $125 million up to $163 million). The purpose of the slides was to provide real life examples to give a sense of how much projects cost and the impact of pore space. 2:00:12 PM Representative Hannan looked at the row in the capital expenditures column of the examples showing the owner's cost. She asked if that reflected the contractor or developer cost for Alaska. She noted that Alaska would be the owner of the pore space. She asked if the pore space lease cost was borne solely by the developer. She noted that in some of the examples discussed, Alaska was the owner of the space and perhaps a developer in some regard. Mr. Fulford replied that the owner's costs predominately related to the surface facilities and were typically paid by the developer. He noted that the legal and regulatory arrangement surrounding the ownership of pore space in Alaska was well defined in its constitution. He stated that generally the costs would be sustained by the developing company and not the state. Representative Hannan stated her understanding there was not currently an example of an LNG/CO2 exchange because it was not happening anywhere yet. She noted that under the concept of the LNG project in Alaska, the state would own the project and would invest in its development. She asked for verification that Alaska expected to be the owner of the sequestration pore space and the owner of the accompanying facilities. Mr. Fulford replied that the concept of the export of LNG and import of CO2 was in the distant future and may not be feasible given it was so far away; however, in the context of the LNG project, he envisioned that a project of that scale and complexity would require a series of legislative steps to go forward (which was the case in most countries GaffneyCline worked with in terms of LNG development). The default assumption would be that the LNG project would pay a tariff to a T&S company to deal with its CO2. He remarked that it could be done in a different way, which had more synergies for the state and the way its revenues were determined. 2:03:34 PM Representative Stapp observed that the examples used a 12- year operating capacity time in the formula used. He asked if it was standard in the industry to amortize costs over 12 years. He highlighted that the pieces of legislation under discussion had a much longer timeframe. Mr. Fulford responded that the 12 years was a throwback to the previous 45Q [tax] structure. He relayed that 20 years would be more typical injection framework and possibly longer. Representative Stapp asked if a 20-year calculation would reduce the cost because there would be 20 years of capital expenditures versus 12. Mr. Fulford responded in the affirmative. He stated that with discount rates, the later years started to have less effect. He relayed that for most companies looking at developments, being able to secure the longest possible secured cashflow was advantages for everyone and resulted in lower tariffs. Representative Stapp asked if the increase of the per tonnage fees to the allowable federal 45Q tax credits was incorporated into the cost assessments. He believed it was $85 per ton for standard capture and he understood it was considerably higher for direct-year capture at $180 [per ton]. Mr. Fulford replied that he was frequently asked how to factor in 45Q and was it considered a credit or revenue. He explained that GaffneyCline considered the 45Q tax cashflow and the associated direct pay to be revenue. For example, if the levelized cost was $50 per ton (which may be typical for a gas processing plant) and a tax credit could be secured at $85 (for a limited time), it would be considered as a profitable project with an IRR [internal rate of return] of potentially greater than 10 percent. Representative Stapp remarked that the cost per ton for carbon storage was less than the available 45Q tax credit. He remarked on the seven-year period. He asked if the difference in the capital expenditure cost of the project was factored in. He stated a project would not be paying any taxes at a federal level even if it was a subsidy. Alternatively, he asked whether the effective credit made a project economical or not was used as a baseline. Mr. Fulford responded that the capital investment and operating expenditures involved in a CCUS project was purely a cost and unless there was a revenue mechanism to compensate, no investment would happen. He noted it was the reason nothing was happening despite the interest in CCUS from a lot of countries. There was an emissions trading system in Europe, which was about $100 per ton. There was the LCFS [low carbon fuel standard] in California, which was similar depending on how much could be captured. Additionally, there was the federal 45Q. He explained it was providing a very significant financial incentive. He highlighted an LNG pre-treatment plant already producing CO2 as an example. He stated it was roughly adequate for something like an ammonia or hydrogen plant, and inadequate for a gas-fired power station. He explained there was a merit order of projects, some were economic and others were not and the cutoff was somewhere between a large hydrogen plant and a gas-fired power station. 2:08:38 PM Co-Chair Johnson thought Mr. Fulford had stated that some of the carbon capture technology was not yet available. She asked what kind of carbon emissions load existed that may be transported to Alaska. Mr. Fulford replied that the largest projects being discussed in Texas were 100 MPTA (the Exxon Houston ship channel project). There was also an existing pipeline that would take 16 MTPA. He noted that in the context of industrial emissions across the country it was minimal. The limitation was the economics of capture. Co-Chair Johnson referred to the monitoring equipment (capital and operating) costs. She assumed that the standards from the registry would drive what the monitoring equipment would be. Mr. Fulford responded affirmatively. He relayed that all of the projects had to obtain a license from the EPA [Environmental Protection Agency] or from the state authority depending on the jurisdiction. He stated it would determine the extensive array of surface and surface monitoring to examine what was happening to the plume and check for any leakage. Co-Chair Johnson surmised it applied to carbon and the Alaska Gasline Development Corporation (AGDC) depending on whether there was a line or other types of equipment installed. She asked how 404 primacy would impact the capital costs. She asked if Mr. Fulford anticipated any difference in the capital cost if the state assumed it. Mr. Fulford replied that the capital investment would probably not change, but the operating expenditure may be reduced. He elaborated that based on some of the projects GaffneyCline was working on, the cost of an EPA class VI permit application was relatively high but expected to drop. He remarked that for states with primacy, the class VI process was perceived to be much less complex. Co-Chair Johnson wondered how familiar Mr. Fulford was with companies' financing based on zero carbon emissions. For example, project financing where zero carbon emissions was a requirement or provided a given number of points towards obtaining a loan. Mr. Fulford summarized that he was very familiar with the topic, which likely warranted a separate discussion. He explained there were clear examples of low carbon projects attracting low cost finance from different sources. There were an increasing number of financial organizations that would deprioritize or not lend to projects they perceived to be incompatible with their carbon goals. Additionally, some of the tech companies with a particularly aggressive net zero target would pay several hundred dollars per ton for a CO2 removal credit. 2:14:41 PM Co-Chair Edgmon stated his understanding that three states had 404 primacy including Florida, New Jersey, and Michigan. He asked if all three states were doing carbon capture. JOHN CROWTHER, DEPUTY COMMISSIONER, DEPARTMENT OF NATURAL RESOURCES, responded that the 404 primacy was distinct from the class VI primacy. He did not know the status of carbon projects in the three states mentioned by Co-Chair Edgmon, but it was not dependent or associated with 404 primacy. He clarified that the class VI primacy through the EPA was for sequestration wells. Co-Chair Edgmon stated that was his understanding. He thought the exchange between Co-Chair Johnson and Mr. Fulford could have been inferred differently. 2:15:33 PM Mr. Fulford advanced to slide 8 titled "Supply, Demand and Levelized Cost." He highlighted a scenario turning the cost breakdown on slide 7 into a tariff excluding the pore lease cost spaces and the other significant commercial risks, the levelized cost or tariff would likely be about $10 to $12 per ton. He stated there seemed to be a price of about $20 per ton that would support some of the larger T&S projects serving the Gulf Coast. The slide highlighted there was a substantial amount of sequestration potential available in the U.S. and to be competitive it was necessary to be at the lefthand side of the curve shown on slide 8. He used the ExxonMobil Houston ship channel project (the largest envisaged project) as an example with 100 MTPA for 20 years, which was about 2 gigatonnes and on the left side of the chart. He relayed that Alaska was perceived to have about 50 gigatonnes available in the Cook Inlet, which was also still very much on the lefthand side of the chart. Mr. Fulford briefly turned to slide 9 showing a summary of some of the leasing fees other states had been securing. He turned to slide 10 titled "Alaska Considerations." He relayed that on a technical level, most of the Gulf Coast projects were aimed exclusively at saline aquifers (water carrying geological formations), which had an extensive but less well defined CO2 storage capacity. The focus in Alaska was currently on depleted gas reservoirs, which were well documented and with very clear traps. The largest difference conceptually between Alaska and other parts of the U.S. was that Alaska had very low state emissions. He discussed the three benefits of Alaska pursuing a CCUS strategy. The first was that the foundation of the Alaska economy continued to be the oil and gas industry. He stated that as all of the recent developments had served to underline, to enable the industry to continue to make the future tax revenues more resilient, an assertive and clearly established carbon management strategy would be needed to help go forward. He elaborated that not only would it protect existing revenues and cashflow, it would potentially secure new investments and future tax royalty that may otherwise be at risk in a world without carbon management. 2:19:37 PM Mr. Fulford relayed that the second benefit was the LNG project (the monetization of North Slope natural gas). He stated that having a robust carbon management strategy to accompany the project would be an essential part of the project going forward from a "social license" perspective. He shared that based on his experience speaking with Japanese banks and others who could conceivably be interested, it was clear that lending to such a project would be dependent on it being presented in a low carbon fashion. He explained that natural gas and carbon capture were two foundation stones of the ammonia and hydrogen industry, which would be an important feature going forward. The third benefit the potential for Alaska to participate in the large scale imports of CO2. Representative Josephson noted that he was a big supporter of the large diameter gasline proposed in past legislation, SB 138 [legislation proposed by former Governor Sean Parnell in 2014] and could see how "this" could be helpful to that endeavor. He considered the subject of social license [in regard to CCUS projects being a catalyst for LNG/gas monetization (shown on slide 10)]. He asked if it could potentially less helpful if the goal post on the international scene moved, which was likely to happen. For example, if the Paris Accord became the Barcelona Accord and had more aggressive goals to achieve. He asked if the consideration could become outdated because the world was in crisis. Mr. Fulford responded that it was a very topical question. He stated that part of his role at GaffneyCline was to take a view on gas and LNG demand and how it was unfolding. Currently there was likely a bigger gap in LNG forecasts, particularly in the post 2030 era. He considered the investment required to move the world's energy systems to a renewable or net zero system and the ability of global economies to sustain the expenditure. He explained it was difficult to create the circumstance where rapid decarbonization would occur. He believed taking a more balanced view of the role that unmitigated natural gas or low carbon fuels like ammonia or hydrogen would take and looking at the timeframe for the Alaska LNG project, it should be a viable proposition with the right buyer and contract structure. He noted that much would depend on the willingness of buyers to invest. 2:23:31 PM Mr. Fulford provided conclusions on slide 11. He relayed that the commercial framework for CCUS was rapidly evolving; however, the tariffs and price point based on the hardware and required capital expenditure were beginning to come together. The capture economics continued to be the biggest part of the equation and getting those addressed was perhaps the key to large scale CCUS. The commercial terms varied significantly depending on the risk allocation. In particular, currently the biggest stumbling block was the ability of an emitter to guarantee off taker. He explained that an emitter would always want its CO2 to be taken, but a storage project may not always be able to take it. There was currently a very active negotiating dialogue in the U.S., from which there were many lessons to be learned in Alaska. Much of the same dialogue was being held outside the U.S. at the government level, with a bit slower pace and a different set of cost drivers. Representative Ortiz looked at slide 11 and asked for an explanation of the bullet point: "commercial terms depend heavily on project structure and risk allocation." Mr. Fulford responded with an example. He explained that once a large industrial emitter secured sequestration, it was able to collect the 45Q [tax credit] and perhaps a premium for low carbon fuel. However, if the emitter was unable to secure the emissions, it may face liabilities of $100 to $300 per ton for having to vent the CO2, or not. On the other hand, the storage entity may be paid $20 per ton to take the CO2. He clarified that the emitter was ideally not about to take a $300 liability for not doing so. He explained that the back and forth on short and long-term liabilities could create some large, stranded costs, which had to be somehow allocated in the contract framework. 2:26:30 PM Co-Chair Edgmon asked how Mr. Fulford would respond to the viewpoint that the idea of carbon capture could be considered a Ponzi scheme. He reasoned that by the time much of the factors were worked out, particularly on the sequestration side, the planet may have pivoted to more carbon friendly in terms of emissions. He considered that idea seemed promising in the current environment but may not bear out in the future. He referenced the continued use of the word "emerging" [used to describe carbon capture technology]. He asked what Mr. Fulford would say to a person who thought the idea sounded like crypto currency or something similar. He stated that the end goal was to not just provide environmental social government (ESG) licenses to an emitter, but to actually reduce carbon. He asked what would happen if it did not pan out and the multibillion dollar emerging industry began to sputter and disappear. Mr. Fulford replied that real money was currently being deployed into CCS from credible and respectable institutions including pension funds and New York based infrastructure funds. Secondly, the International Panel on Climate Change (IPCC) was pushing hard for a rapid decarbonization of the world's economy. He elaborated that the IPCC had stated that CCUS was an essential part of the transition from present to net zero. He considered some of the transformational energy systems like fusion and imagined that in 50 or so years carbon capture would be an older technology; however, there was a very clear role for the next 50 years and investment was taking place currently. Co-Chair Edgmon thanked Mr. Fulford for the presentation. Co-Chair Foster thanked Mr. Fulford and set an amendment deadline for May 10, 2023, at 5:00 p.m. HB 50 was HEARD and HELD in committee for further consideration. 2:30:49 PM AT EASE 2:32:34 PM RECONVENED